Enable Midstream Partners, LP
MLPA 2017 Investor Conference Presentation
June 1, 2017
Rod Sailor
President & CEO
Forward-Looking Statements
This presentation and the oral statements made in connection herewith may contain “forward-looking statements” within
the meaning of the securities laws. All statements, other than statements of historical fact, regarding Enable Midstream
Partners’ (“Enable”) strategy, future operations, financial position, estimated revenues, projected costs, prospects, plans
and objectives of management are forward-looking statements. These statements often include the words “could,”
“believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast” and similar expressions and are intended to
identify forward-looking statements, although not all forward-looking statements contain such identifying words. These
forward-looking statements are based on Enable’s current expectations and assumptions about future events and are
based on currently available information as to the outcome and timing of future events. Enable assumes no obligation to
and does not intend to update any forward-looking statements included herein. When considering forward-looking
statements, which include statements regarding future commodity prices, future capital expenditures and our financial
and operational outlook for 2017, among others, you should keep in mind the risk factors and other cautionary
statements described under the heading “Risk Factors” and elsewhere in our SEC filings. Enable cautions you that these
forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many
of which are beyond its control, incident to the ownership, operation and development of natural gas and crude oil
infrastructure assets. These risks include, but are not limited to, contract renewal risk, commodity price risk,
environmental risks, operating risks, regulatory changes and the other risks described under “Risk Factors” and
elsewhere in our SEC filings. Should one or more of these risks or uncertainties occur, or should underlying assumptions
prove incorrect, Enable’s actual results and plans could differ materially from those expressed in any forward-looking
statements.
2
Forward-Looking Non-GAAP Financial Measures
3
Enable has included the forward-looking non-GAAP financial measures Adjusted EBITDA, Adjusted interest expense, Distributable
cash flow and Distribution coverage ratio in this presentation based on information in its condensed consolidated financial
statements.
Adjusted EBITDA, Adjusted interest expense, Distributable cash flow and Distribution coverage ratio are supplemental financial
measures that management and external users of Enable’s financial statements, such as industry analysts, investors, lenders and
rating agencies may use, to assess:
• Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry,
without regard to capital structure or historical cost basis;
• The ability of Enable’s assets to generate sufficient cash flow to make distributions to its partners;
• Enable’s ability to incur and service debt and fund capital expenditures; and
• The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment
opportunities.
This presentation includes a reconciliation of Adjusted EBITDA and Distributable cash flow to net income attributable to limited
partners and Adjusted interest expense to interest expense, the most directly comparable GAAP financial measures, as applicable,
for each of the periods indicated. Distribution coverage ratio is a financial performance measure used by management to reflect the
relationship between Enable's financial operating performance and cash distributions. Enable believes that the presentation of
Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow and distribution coverage ratio provides
information useful to investors in assessing its financial condition and results of operations. Adjusted EBITDA, Adjusted interest
expense, Distributable cash flow and distribution coverage ratio should not be considered as alternatives to net income, operating
income, revenue, cash flow from operating activities, interest expense or any other measure of financial performance or liquidity
presented in accordance with GAAP. Adjusted EBITDA, Adjusted interest expense, Distributable cash flow and distribution
coverage ratio have important limitations as analytical tools because they exclude some but not all items that affect the most directly
comparable GAAP measures. Additionally, because Adjusted EBITDA, Adjusted interest expense, Distributable cash flow and
distribution coverage ratio may be defined differently by other companies in Enable’s industry, its definitions of these measures may
not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Contents
Enable Midstream Overview
Recent Commercial Successes
Key Takeaways
Appendix
4
Enable Midstream Overview
5
Enable Midstream Highlights
Strong customer relationships and high-quality assets in top-tier plays
• Assets are located in some of the most prominent natural gas and crude oil plays in the country
• High degree of interconnectivity between assets and end markets
• Full range of midstream services for growing producer supply and market demand
• Long-term relationships with large-cap producers and utilities, many of whom are investment grade
Strong financial position
• Favorable contract structure with significant fee-based and demand-fee margin
• Demonstrated access to both equity and debt capital markets
• ~$1.75 billion of available revolving credit facility capacity and no near-term debt maturities1
• Continue to prioritize leverage and coverage ratios while remaining financially disciplined
6
Bradley Processing Complex
1. As of March 31, 2017
Interconnected & Diverse Assets Strategically-located assets connect producer supply to end markets
7
Note: Map as of May 10, 2017; Completion of the announced Wildhorse plant has been deferred
1. As of March 31, 2017; includes ~7,800 miles of interstate pipeline, including SESH, and ~2,200 miles of intrastate pipelines
2. As of December 31, 2016
~12,900 miles Gathering pipeline2
~10,000 miles Interstate/intrastate pipelines1
85 Bcf Storage capacity2
2.5 Bcf/d Processing capacity2
8
Substantial
Size & Scope
Favorable Balance
Sheet & Liquidity
Position
Growing G&P
Volumes
Strong Financial
Performance &
Fee-Based Margin
• Total market capitalization of ~$7 billion1
• 2017 Net Income outlook: $315 - $385 million2
• 2017 Adj. EBITDA outlook: $825 - $885 million2,3
• Investment grade credit metrics
• Total Debt / Adj. EBITDA below 3.5x as of March 31, 2017
• ~$1.75 billion of available revolving credit facility capacity4
• 5 consecutive quarters of natural gas gathered volume growth4
• 3 consecutive quarters of natural gas processed volume growth4
• Adj. EBITDA increased by ~9% in 2016 compared to 2015
• Achieved highest distributable cash flow in 2016 since inception
• ~93% fee-based or hedged 2017 gross margin profile5
Financial & Operational StrengthWell-positioned for continued growth
1. As of May 24, 2017
2. 2017 Outlook as of May 3, 2017; Net Income represents net income attributable to common and subordinated units
3. Non-GAAP financial measure is reconciled to the nearest GAAP financial measure in the appendix
4. As of March 31, 2017
5. Per hedges as of April 11, 2017, and Enable’s April 2017 price assumptions; represents gross margin for Q2-17 through Q4-17
9
Perryville Hub
Note: Map as of May 10, 2017
1. For the twelve months ending on December 31, 2016; excludes SESH which is reported as an equity method investment
2. 50/50 joint venture with Spectra Energy Partners, LP
EGT(Enable Gas
Transmission)
MRT(Mississippi River
Transmission)
SESH(Southeast Supply
Header)
• Serves utilities, end-users and producers, providing access to Mid-continent supply and
other Northeastern, Mid-continent and Gulf Coast markets through interconnects
• Serves utilities and end-users, providing access to Mid-continent supply and
Northeastern supply through interconnects
• Primarily serves customers that generate electricity for the Florida power market and
interconnects to pipelines serving major Southeast and Northeast markets
• Serves utilities, end-users and producers, including growing Anadarko Basin
production
EOIT(Enable Oklahoma
Intrastate Transmission)
System Map & Highlights
2
T&S Gross Margin1
98% Derived from
Fee-Based ContractsSignificant Percentage
of Total Gross Margin
Transportation & Storage Segment
EOIT
EGT
EGT*59%
MRT*14%
EOIT*20%
Volume Dependent 5%
T&S 42%
G&P58%
*Firm Contracts
10
Gathering & Processing SegmentSystem Map & Highlights
Significant Fee-
Based Margin1
2.45 Bcf/d
Processing
Capacity1
6.9 Million Gross
Acres of
Dedications1
32 Active Rigs on
Footprint2
Note: Map as of May 10, 2017
1. For the twelve months ending on December 31, 2016
2. Contractually dedicated rigs to Enable per Enable’s quarterly earnings press releases
34%MVC Fee-
Based
44%Volume
Dependent Fee-Based
22%Commodity-
Based
22
9
1
Anadarko Ark-La-Tex Williston
Anadarko: 1.845 Bcf/d
Anadarko: 4.8 million
Arkoma: 1.4 million
Ark-La-Tex: 0.7 million
Ark-La-Tex: 0.545 Bcf/d
Arkoma: 0.060 Bcf/d
Enable Dedicated Rig Activity1
Well-Positioned in Top-Tier Plays
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SCOOP/STACK and Haynesville rig activity to drive long-term volume growth
We believe that the gas price necessary to yield a
10% rate of return on invested capital (in
Haynesville) to be below $2.05 for our standard
laterals and below $1.80 for long laterals.
Vine Resources Inc. Form S-1 Filing, May 2017
As of December 31, 2016, we had identified over
2,700 gross operated horizontal drilling locations in
the NW Stack, providing us with a multi-decade
drilling inventory.
Tapstone Energy Inc. Form S-1 Filing, April 2017
When you’re working on a petroleum system as
extensive as SCOOP and STACK, results generally
keep getting better and new reservoirs emerge.
That is definitely what we are seeing.
Continental Resources, May 2017
1. Rigs contractually dedicated to Enable; per Drillinginfo as of April 17, 20172. Per Wood Mackenzie – North American Gas Tool as of May 24, 2017
5.3
9.0
2017 2027
1.8
2.9
2017 2027
SCOOP/STACK/Cana
Woodford
Haynesville
Bcf/d
Bcf/d
+1.1Bcf/d
+3.7Bcf/d
10-Year Supply Outlook2
Producer Customer Commentary
22 22 23 2320
4 47 9 9
Q1-16 Q2-16 Q3-16 Q4-16 Q1-17
SCOOP/STACK Haynesville
Appendix
12
Recent Commercial Successes
Over 1 Bcf/d of Recently Contracted Market
Solutions for Growing SCOOP & STACK Production
13
Capital-Efficient Expansion Projects Provide Critical Access to Premium Markets
Note: Map as of May 10, 2017; Completion of the announced Wildhorse plant has been deferred
1. Initial capacity of 45 MMcf/d in early 2018, growing to full 205 MMcf/d by Q4-2018
Tolar Hub
Bennington
Perryville Hub
TGT Helena
TexasMarkets
~400MMcf/d
Bennington &Southeast
Markets
~600MMcf/d
CaSE Project1
In-service Expected Q4-2018
Project WildcatIn-service Expected Q2-2018
Line AD ExpansionIn-service Q2-2017
Bradley LateralIn-service Q4-2015
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Note: Processing capacity per Bentek as of May 8, 2017; represents processing capacity in designated SCOOP and STACK counties where SCOOP is designated
as Caddo, Carter, Garvin, Grady, McClain and Stephens counties of Oklahoma and STACK is designated as Blaine, Canadian, Custer, Dewey, Kingfisher, Major
and Woodward counties of Oklahoma
1. Represents the 400 MMcf/d of processing capacity provided at the Godley Plant in Johnson County, Texas, for incremental gathered volumes in the
Anadarko Basin; capacity estimated to be available by the end of Q2-2018
+600MMcf/d
New market solutions announced in 2017
+400MMcf/d
Additional processing capacity for
SCOOP and STACK production
2018 DCFExpected to be accretive to 2018 distributable cash flow
1
Project Wildcat
Enable to deliver
approximately 400
MMcf/d of rich
natural gas from the
Anadarko Basin for
processing at the
Godley Plant in
Johnson County,
Texas
CaSE Project
10-year, 205 MMcf/d
firm natural gas
transportation
agreement provides
a transportation
solution out of the
Anadarko Basin with
access to Southeast
markets
TOP 5 SCOOP/STACK PROCESSING CAPACITY
Creative & Capital-Efficient Anadarko Basin Market Solutions
Project Wildcat & CaSE Project
1.571.61 1.62
1.66 1.67
1.75
Project Wildcat Positions Enable for Further
Anadarko Basin Growth
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Note: Map as of May 10, 2017; Completion of the announced Wildhorse plant has been deferred
1. Includes the 400 MMcf/d of processing capacity provided at the Godley Plant in Johnson County, Texas, for incremental gathered volumes in the Anadarko
Basin; capacity estimated to be available by the end of Q2-2018
Increases
Processing
Capacity for
Anadarko Basin
Production1
~2.25Bcf/d
1.85Bcf/d
2.25Bcf/d
2016 Projected2018
Gathered VolumesTBtu/d
22% Increase
Processed VolumesTBtu/d
1.39 1.41
1.44
1.50 1.52
1.54
+11.5%
+10.8%
1
AppendixKey Takeaways
16
Key Takeaways
17
• Assets are located in prominent natural gas and crude oil producing basins with a
market-leading midstream position in the SCOOP and STACK plays
• Significant drilling activity in areas served by gathering and processing assets
• Well-positioned to support the long-term supply and demand dynamics in the Mid-
Continent, Gulf Coast and Southeast regions
• Fully integrated suite of assets: ~12,900 miles of gathering systems, 14 major
processing plants with 2.5 Bcf/d of processing capacity, ~7,800 miles of interstate
pipelines1, ~2,200 miles of intrastate pipelines and eight storage facilities comprising
85.0 Bcf of storage capacity
• High degree of interconnectivity between assets and end markets and consumers
• Favorable contract structure with significant fee-based and demand-fee margin
• Long-term contracts with large-cap producers and utilities, many of whom are
investment grade
• Continue to prioritize efficient capital deployment and cost discipline
• Investment grade credit metrics and $1.75 billion of available revolver capacity2
• Strong distribution coverage and consistent distributions to unitholders
Strategically
Located
Assets
Significant
Size &
Scale
Long-term,
Fee-Based
Contracts
Financially
Disciplined
1. Includes SESH, in which Enable owns a 50% interest2. As of March 31, 2017; available liquidity calculated as Revolving Credit Facility of $1.75B less $3MM in letters of credit
Appendix
18
Appendix
2017 Outlook
19
$ in millions
Net Income Attributable to Common
and Subordinated Unit Holders$315 – $385
Interest Expense $114 – $122
Adjusted EBITDA1 $825 – $885
Preferred Equity Distributions2 $36
Adjusted Interest Expense1 $120 – $130
Maintenance Capital $95 – $125
Distributable Cash Flow1 $555 – $605
Distribution Coverage Ratio 1.0x or greater
Note: 2017 Outlook as of May 3, 2017; Original 2017 outlook released on November 2, 2016
1. Financial measures are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures in the appendix
2. Includes the fourth quarter 2017 distribution that will be paid in the first quarter 2018
3. 2017 gross margin is based on hedges as of April 11, 2017, and Enable’s April 2017 price assumptions; represents gross margin for Q2-17 through Q4-17
4. NGL composite based on assumed composition of 45%, 30%, 10%, 5% and 10% for ethane, propane, normal butane, isobutane and natural gasoline,
respectively
2017 Expansion Capital Outlook
$ in millions
Gathering and Processing $425 – $515
Transportation and Storage $75 – $85
Total Expansion Capital $500 – $600
2017 Financial Outlook
53%32%
8%7%
Firm/MVC Fee-based Other Fee-based
Commodity-based Hedged Commodity-based Unhedged
2017 Gross Margin Profile3
~93% fee-
based or
hedged
Natural Gas Gathered Volumes (TBtu/d) 3.3 – 3.8
Anadarko 1.7 – 2.0
Arkoma 0.5 – 0.7
Ark-La-Tex 0.9 – 1.3
Natural Gas Processed Volumes (TBtu/d) 1.9 – 2.3
Anadarko 1.6 – 1.9
Arkoma 0.1 – 0.2
Ark-La-Tex 0.1 – 0.3
Crude Oil – Gathered Volumes (MBbl/d) 23.0 – 28.0
Interstate Firm Contracted Capacity (Bcf/d) 6.1 – 6.5
2017 Operational Outlook
Enable Ownership Structure
20
Rig Activity Remains Strong
21
STACK & SCOOP Acreage and Activity1 Haynesville Activity1
Note: Maps as of May 10, 2017; Completion of the announced Wildhorse plant has been deferred
1. Rigs per Drillinginfo as of April 17, 2017
Price Sensitivities
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1. Price sensitivities are for the nine months ending December 31, 2017; based on current prices and current hedges2. The impact of price sensitivities is the same for net income attributable to limited partners and net income attributable to common and subordinated units
Impact to 2017 Net Income (including impact of hedges)2
% Change in Prices
$ in millions +10% -10%
Natural Gas and Ethane $1 ($2)
NGLs (excluding ethane) and Condensate $3 ($3)
Impact to 2017 Adjusted EBITDA (including impact of hedges)
% Change in Prices
$ in millions +10% -10%
Natural Gas and Ethane $2 ($2)
NGLs (excluding ethane) and Condensate $4 ($4)
2017 Price Sensitivities1
2017 Hedging Summary
23
1. Table includes 2017 hedges and commodity exposures associated with equity volumes resulting from Enable's Gathering, Processing and Transportation businesses; percentage hedged includes hedges executed through April 14, 2017 for Q2-17 through Q4-17
2. Enable hedges net condensate/natural gasoline exposure with crude
Commodity 2017
Natural Gas
Exposure Hedged (%) 64%
Average Hedge Price ($/MMBtu) $2.72
Crude3
Exposure Hedged (%) 67%
Average Hedge Price ($/Bbl) $51.32
Propane
Exposure Hedged (%) 65%
Average Hedge Price ($/gal) $0.50
Forward Looking Non-GAAP Reconciliation
24
1. Outlook includes the fourth quarter 2017 distribution that will be paid in first quarter 2018
2017 Outlook
(In millions)
Reconciliation of Adjusted EBITDA and distributable cash flow
to net income attributable to limited partners:
Net income attributable to common and subordinated units $315 - $385
Add:
Series A Preferred Unit distributions 36
Net income attributable to limited partners $351 - $421
Depreciation and amortization expense 350 - 360
Interest expense, net of interest income 114 - 122
Income tax expense 0 - 5
Distributions from equity method affiliates 32 - 36
Non-cash equity based compensation 12 - 16
Change in fair value of derivatives (25 - 35)
Equity in earnings of equity method affiliates (22 - 28)
Adjusted EBITDA $825 - $885
Less:
Series A Preferred Unit distributions(1) 36
Adjusted interest expense 120 - 130
Maintenance capital expenditures 95 - 125
Current income taxes —
Distributable cash flow $555 - $605
Forward Looking Non-GAAP Reconciliation
Continued
25
Enable is unable to present a quantitative reconciliation of forward looking Adjusted EBITDA to Net Cash Provided by
Operating Activities because certain information needed to make a reasonable forward-looking estimate of changes in working
capital which may (provide) use cash during the calendar year 2017 cannot be reliably predicted and the estimate is often
dependent on future events which may be uncertain or outside of Enable's control. This includes changes to Accounts Receivable,
Accounts Payable and Other changes in non-current assets and liabilities.
2017 Outlook
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest Expense $114 - $122
Add:
Amortization of premium on long-term debt 5
Capitalized interest on expansion capital 0 - 6
Less:
Amortization of debt costs (0 - 4)
Adjusted interest expense $120 - $130